In the production of water, oil and gas from subterranean formations, scale deposits can frequently result in: plugged well bores, plugged well casing perforations, plugged tubing strings, stuck downhole safety valves as well as other valves, stuck downhole pumps and other downhole and surface equipment and lines, scaled formations and fractures in the vicinity of the well. Such scale formation can occur as a result of mixing of incompatible waters in the well, i.e., waters which when mixed produce precipitates, or as a result of temperature and pressure changes and the like in the produced waters during production. Generally, incompatible waters are formed as a consequence of waterflooding, as injected sea water mixes with formation water in the borehole during water breakthrough. The more common concern is scales deposited because of changes in supersaturation or solubility of minerals in the formation or produced waters caused by pressure and temperature changes, or changes in other physical and chemical environments such as gas compositions, ratio of gas/oil/water. Precipitation frequently encountered as scale include calcium carbonate, calcium sulfate, barium sulfate, magnesium carbonate, magnesium sulfate, and strontium sulfate. The deposition of scale is a very complex crystalline process initiated by a supersaturation-induced nucleation of a precipitate of the mineral, scale ions contact these nuclei and the crystal grows in certain crystalline pattern. The adherence of these mineral crystals unto the formation matrix, perforation, well-bore, tubings and equipment is a not well-understood process but once initiated, appears to be spontaneous as seen by the increasing thickness of the scale deposit and the steady decline in productivity. In some cases, production can be halted when valves and pumps are stuck--creating a potentially dangerous situation. The normal practice of treating with inhibitors does protect scales from forming in the perforations or near well-bore areas, well tubulars, downhole pump, other downhole equipment, and surface equipment. But such practice results in very short life requiring frequent re-treatments and necessitating periods of loss production. A significant extension of life means that down-times due to re-treatments will be much less frequent translating to better economics of operation.
The squeezing of chemicals for protecting wells, particularly oil wells, is widely practiced. A "squeeze" job might last one to six months depending on the nature of the subterranean formation into which the chemical is squeezed and the rate at which fluids e.g., oil and water, are produced by the well. A formation that has low permeability but high porosity, and from which low rates of oil and water are produced would likely bleed injected chemicals back for a long time. However, a problem arises with highly permeable formations which produce high rates of oil and water. This type of formation retains chemicals for only a short time because they are readily washed out of the permeable zones of the formation by the high volumes of produced fluids. The inhibitor is normally retained by an adsorption mechanism into the formation matrix and released by desorption during fluids production. In general, at least a third or more of the inhibitor is not absorbed but is immediately produced back, resulting in ineffective use and frequent retreatments.
In an article by Carlberg and Essel entitled, "Strontium Sulfate Scale Control by Inhibitor Squeeze Treatment in the Fateh Field", published in the Journal of Petroleum Technology, in Jun. 1982, there is disclosed a method for inhibiting scale formation in a subterranean limestone formation by injecting an acid form of a polyphosphonate which forms a slightly soluble calcium salt. Calcium ions released on dissolution of some of the limestone (calcium carbonate) rock by the acid precipitates calcium polyphosphonate allowing greater retention in the rock. However, this method does not work in sandstones, because sandstones are not soluble in acids, nor do they form calcium ions even when dissolved.
U.S. Pat. No. 3,827,977 to L. H. Miles and G. E. King, issued Aug. 6, 1974, discloses a method of increasing retention of an inhibitor by in situ formation of the relatively water or brine insoluble polycation salt of polyacrylic acid or hydrolyzed polyacrylamide. A strong acid solution (pH less than 1.5) used initially inhibits reaction of the polycation with the polyacrylic acid but the acid is eventually neutralized by the formation rock allowing the deposition of the water insoluble metal salt of the inhibitor in the formation. In the practice of the Miles et al invention, a larger than stoichiometric amount of the polyvalent metal salt (with Ca.sup.+2 and Zn.sup.+2 preferred) associated with the carboxylic acids groups of the inhibitor is required to insure complete reaction of the inhibitor (i.e., equivalent ratio of polyvalent metal cation to carboxylic acids greater than 1.0). For example, Miles et al cites a concentration of about 0.5 to 1.5% solutions by weight Ca.sup.+2 with 0.5 to 1% solutions of the sodium polyacrylate. Assuming a molecular weight of 5000 for the polyacrylate (at 1% by weight) and Ca.sup.+2 at 0.5%, the equivalent ratio of Ca to carboxylic acid groups is 1.8; while the mole ratio of Ca to polyacrylate is 62.5. The limiting factor in the use of such high concentrations of multivalent metal ions is the danger of damaging the formation by plugging it with premature precipitation. In an article by K. O. Meyers et al, entitled "Control of Formation Damage at Prudhoe Bay, Ark., by Inhibitor Squeeze Treatment", published in the Journal of Pet. Tech., pp 26, in Jun. 1985, they caution against the presence of high concentrations of calcium when the inhibitor is squeezed into a well for the same reason. The normal criteria for selection of an inhibitor includes having high solubility in the reservoir brine and low susceptibility to precipitation by divalent cations. Therefore, introduction of the inhibitor in the manner taught by Miles et al affords little or no protection in inhibiting premature precipitation that causes plugging of the formation.
British Patent 1290554, to M. J. D'Errico and S. F. Adler discloses a process of treating an oil well to inhibit the formation of hard scale by the precipitation from the oil well brine of scale-forming water-insoluble salts. The process comprises converting water-soluble polyacrylate scale inhibitors to a solid water insoluble polymer by reaction with polyvalent metal cations. The solid water insoluble polymer is injected into the formation in conjunction with fracture treatments. The solid water insoluble polymer is required to be insoluble in water at 25.degree. C. at a concentration of more than 50 ppm.
According to the present invention the danger of damaging the formation by precipitation is avoided by limiting the equivalent ratio of multivalent cations to inhibitor to a ratio of 0.5 or less, injecting the inhibitor in an aqueous solution having a pH effective to form a water-soluble complex of the inhibitor and the polyvalent cation, preferably in the range of 2 to 3, and limiting inhibitor molecular weight range to 500 to 10,000 which extends the life of the polyacrylate inhibitor 2 to 5 times that of a similar treatment without the polyvalent cation. Furthermore, at these low polyvalent cation concentrations, the polyacrylic inhibitor is very active while the activity is diminished significantly at a high polyvalent cation concentration (equivalent ratio greater than 0.5). Injecting the inhibitor and the polyvalent cation in an aqueous solution having a pH effective to form a water-soluble complex of the inhibitor and the polyvalent cation increases retention of the inhibitor in the formation. The water-soluble complex is much more adsorptive in sandstones than the inhibitor by itself.